1. Field of the Invention
The present invention relates generally to methods and apparatus for exploring subsurface formations. More particularly, the present invention relates to improved techniques for controlling seismic exploration testing and measurement equipment.
2. Background
Geophysical mapping techniques for determining subsurface structures in the Earth include, for example, seismic surveying, magnetotelluric surveying and controlled source electromagnetic surveying, among others. Generally, a variety of different seismic surveying techniques may be used in performing seismic exploration of different physical environments such as land environments and marine environments. Such seismic surveying techniques may include, for example, surface seismic exploration and borehole seismic exploration.
In surface seismic surveying, an array of seismic sensors is deployed at the Earth's surface (or near the water surface or on the water bottom for various types of marine seismic surveying), and one or more seismic energy sources is actuated at or near the Earth's surface in a location near the seismic sensor array. A record is made, indexed with respect to time of actuation of the seismic energy source, of signals corresponding to seismic energy detected by each of the sensors in the array. Seismic energy travels downwardly from the source and is reflected from acoustic impedance boundaries below the Earth's surface. The reflected energy is detected by the sensors. Various techniques are known in the art for determining the structure of the subsurface Earth formations below and/or adjacent to the sensor array from recordings of the signals corresponding to the reflected seismic energy. Other techniques known in the art provide estimates of fluid content in porous Earth formations from characteristics of the reflected energy such as its phase and/or amplitude.
Borehole seismic surveys are typically conducted by placing receivers in a borehole and operating a seismic source at the surface to generate an acoustic wave. Typically the receivers are placed in a shuttle and deployed downhole for the duration of the survey and then removed.
Seismic data are typically collected using an array of seismic sources and seismic receivers. The data may be collected on land using, for example, vibration devices or explosive charges as sources and geophones as receivers; or the data may be collected at sea using, for example, air guns as the sources and hydrophones as the receivers.
FIG. 1A is a schematic illustration of the survey geometry for the method of seismic surveying known as vertical seismic profiling (VSP) surveying. In this surveying geometry, the receiver 1 is not disposed on the earth's surface, but is disposed within the earth, in this example within a borehole 6. The seismic source 2 is disposed on the earth's surface. Two ray paths for seismic energy are shown in FIG. 1. Path 3 is a path in which the seismic energy does not undergo reflection, although it is refracted at the boundary between two layers 7, 8 of the earth. Since seismic energy that travels along this path travels direct from the source 2 to the receiver 1 without reflection, this path is known as the “direct path”. Path 4 is a path in which seismic energy emitted by the source 2 is incident on the receiver 1 after reflection by a reflector 5 located at a greater depth than the receiver, and is thus known as a “reflection path”.
In FIG. 1A the seismic source 2 is located at a distance from the point at which the vertical line on which the receiver 1 is disposed passes through the earth's surface. This geometry is known as offset VSP, since there is a non-zero horizontal distance between the seismic source and the receiver. The horizontal distance between the seismic source and the receiver is generally known as “offset”. In an alternative VSP geometry, the seismic source is located nearly vertically over the receiver, and this is known as zero-offset VSP.
FIG. 1A shows only one seismic source and one receiver, but it is possible for there to be more than one source and/or more than one receiver. In the survey geometry known as multi-offset VSP, a plurality of seismic sources are located on the surface of the earth, with each source having a different offset (i.e., being at a different horizontal distance from the point at which the vertical line on which the receiver 1 is disposed passes through the earth's surface).
A vertical seismic profile (VSP) is a class of borehole seismic measurements used for correlation between surface seismic receivers and wireline logging data. VSPs can be used to tie surface seismic data to well data, providing a useful tie to measured depths. Typically VSPs yield higher resolution data than surface seismic profiles provide. VSPs enable converting seismic data to zero-phase data as well as enable distinguishing primary reflections from multiples. In addition, a VSP is often used for analysis of portions of a formation ahead of the drill bit.
Conventionally, there are a variety of different VSP configurations including zero-offset VSP, offset VSP, walkaway VSP, vertical incidence VSP, salt-proximity VSP, multi-offset VSP, and drill-noise or seismic-while-drilling VSP. Check-shot surveys are similar to VSP in that acoustic receivers are placed in the borehole and a surface source is used to generate an acoustic signal. However, a VSP is a more detailed than a check-shot survey. The VSP receivers are typically more closely spaced than those in a check-shot survey; check-shot surveys may include measurement intervals hundreds of meters apart. Further, a VSP uses the reflected energy contained in the recorded trace at each receiver position as well as the first direct path from source to receiver while the check-shot survey uses only the direct path travel time.
While VSPs can provide valuable information about a formation, source perturbations (e.g. shot to shot variations in the seismic signature of an air gun) introduce error into the raw seismic data which percolates through the processing chain to the final images produced. VSP source perturbations can limit the full range of usefulness that VSPs data can provide. In marine surface seismic acquisitions, these source perturbations can be well controlled through digital gun controllers and processes such as source signal estimation (see, for example, U.S. Pat. Nos. 4,757,482; 5,581,415; 5,995,905; and 4,476,553, which are hereby incorporated by reference in their entirety for all purposes).
FIG. 1B shows an example of a borehole offset VSP measurement scenario in a marine environment in which an offshore rig 100 is positioned over a subsea borehole 102. The borehole 102 includes a plurality of spaced receivers 103 to facilitate, for example, a vertical seismic profile VSP acquisition. When performing borehole offset VSP measurements in a marine environment, a boat 122 is typically used to transport the seismic signal source equipment to a desired location away from the offshore rig 100.
In the example of FIG. 1B, the seismic signal source equipment which is located at the boat includes an air-gun or guns 106 suspended below the surface by a float 108. An analog hydrophone 110 is suspended below the air-gun 106. The hydrophone 110 can provide partial information for correcting time break errors attributable to time differences for swells, irregular source firings, etc. One or more analog lines form part of an umbilical 111 that may also include an air line. The umbilical 111 provides an analog communications/control link between the boat-side seismic survey computer system 124 and the signal source equipment.
Typically, the rig-side seismic survey computer system 120 and the boat-side seismic survey computer system 124 are initially configured with desired operating parameters before deployment in the field. Once the computer systems have been deployed in the field, a human technician is stationed at each system to operate their respective equipment in order to carry out seismic survey measurements. Communication between the rig-side seismic survey computer system and the boat-side seismic survey computer system is typically implemented using an analog radio communication link.
Conventionally, rig-side seismic survey computer systems and boat-side seismic survey computer systems do not include functionality for enabling remote configuration or modification of their operating parameters. Thus, for example, when the rig-side technician (stationed at the rig-side seismic survey computer system) desires to modify an operating parameter at the boat-side seismic survey computer system, the rig-side technician is required to communicate (typically via radio communication) with the boat-side technician in order to instruct the boat-side technician to modify the desired parameter(s) at the boat-side seismic survey computer system. The boat-side technician is then responsible for implementing the specified parameter modifications at the boat-side seismic survey computer system.
Moreover, due to the complexity of seismic source control operations, conventional source control systems provide only limited quality control (QC) features, and provide only limited functionality for controlling source control equipment, especially for remote source signal and large source arrays. Accordingly, it will be appreciated that there exists a need for improving seismic survey measurement techniques and equipment.